In a wide variety of oilfield treatments, in which treatment fluids are injected into a formation through a wellbore, the formation being treated is stratified. Typically in such stratified formations, the permeabilities of the strata differ, sometimes substantially. Also, typically, one or more of the strata (which for simplicity we will call the oil-containing zone), will contain potentially producible hydrocarbon (oil, condensate, or gas). In this discussion we use the terms “oil-containing” and “hydrocarbon-containing” interchangeably and we use the terms “oil” and “hydrocarbon” interchangeably. Often one or more other strata (which for simplicity we will call the water-containing zone), will contain in its pores entirely, or almost entirely, only formation water or brine and will contain either no hydrocarbon or only residual hydrocarbon remaining after the producible hydrocarbon has already been produced from that zone. This zone will be a good producer of fluid that is all or mostly water. The other zone or zones will be considered problematic because they contain hydrocarbon that is not being produced properly. The zones that are producing fluid, either water or hydrocarbon or both, will be termed “non-problematic” here, even though water production is normally undesirable. By definition, here, the “problem” is that a zone is not producing or not producing satisfactorily, so by this definition a zone that is producing is “non-problematic”. If both oil and water phases are present in a zone, but some or all of the producible oil has been produced, the zone will be considered a water-containing zone; in this case water is typically the continuous phase, and the flowing phase, and the water saturation is high. (However, if the formation is oil-wet, oil could be a thin continuous phase on the pore surfaces but water would still be the flowing phase.) Frequently, it is also true that the permeability to injected fluid of the water-containing zone is greater than the permeability to injected fluid of the oil-containing zone.
In other cases, there is no water-containing zone, but there is permeability stratification of the hydrocarbon-containing zones or strata. In such cases, oil will be produced preferentially from the more permeable zones, termed “non-problematic”. The less permeable zone or zones will be considered problematic because again they contain hydrocarbon that is not being produced properly. They could be problematic because they are inherently less permeable (because of the geology) or because they have been damaged.
In many oilfield treatments, it is desirable to inject all or most of the injected fluid into one or more specific “problematic” oil-containing zones, i. e. stratum or strata that contain potentially producible hydrocarbon that is not or will not be satisfactorily produced, and not into other zones. These zones are “problematic” because they are oil-containing but are not or will not satisfactorily produce the hydrocarbon that they contain. In the situations under consideration here, production from these problematic zones is unsatisfactory because there are more-productive (“non-problematic”) zones. These more productive zones may be water-containing zones that produce water. On the other hand, there may not be water zones, but the problematic zones may inherently have lower permeabilities than the other zones or may have been damaged in a drilling, completion or production process, so that some oil-containing zones can or will produce oil and others can or will not. For example, in hydraulic fracturing (including acid fracturing) an optimal treatment would place the fracture entirely in the problematic zone(s). Similarly, in acidizing treatments (of sandstone formations to remove damage, or of carbonate formations to create flow paths such as wormholes) an optimal treatment would be one in which all the injected fluid was placed in the problematic zone. These requirements are important because the objects of such treatments are to increase the permeability or the volume (or both) of the flow path for fluids in the problematic zone while not creating such increases in water-containing zones, or, if there are no water-containing zones, creating greater increases in the “problematic” zones than in the other zones. Furthermore, treatment fluid injected into a water-containing zone is at best “wasted” (and that zone is often thus called a “thief” zone) even if it does not enhance the flow path there. Worse, treatment fluid injected into a water-containing zone could increase water production. In practice, treatments often do not go primarily into the problematic zones.
In most of the following discussions, the “problematic” zones will be described as though they were problematic relative to water-containing zones, but it should be appreciated that problematic zones may be problematic relative to oil-containing zones. The zones into which it is desired to inject treatment fluids will normally be described as “oil-containing” zones even though in some cases all the zones, including the thief zones, are oil-containing. Typically, undiverted treatments enter thief zones having high water saturation (because the treatments are aqueous) and/or high permeability (because fluids follow the path(s) of least resistance). Methods devised to increase injection into the problematic oil-containing zone, even if it has lower permeability, are called diversion methods, and mechanical devices or chemicals used in them are called diverters. Only chemical diverters will be considered further here.
Some of the simple chemical diverting agents that have been used in the past include oil-soluble resins, water-soluble rock salt, and emulsions. A chemical diverter based on aqueous micellar viscoelastic surfactant gels was described in U.S. Pat. No. 5,979,557 which has a common assignee as the present application. This material will be called “VES Diverter”. VES Diverter is used primarily in acidizing and fracturing; its use in acid diversion is described in Chang, et al, “Case Study of a Novel Acid-Diversion Technique in Carbonate Reservoirs,” SPE paper 56529 (February, 1998). It can be used in both sandstones and carbonates. The surfactants described in U.S. Pat. No. 5,979,557 are amines, amine salts and quaternary amine salts, preferably erucyl bis(2-hydroxyethyl)methyl ammonium chloride, also known as N-cis-13-docosenoic-N,N-bis(2-hydroxyethyl)-N-methyl ammonium chloride. A salt (for example an inorganic salt of Ca, Mg, Zn, Al, or Zr) must be included in the fluid for the fluid to gel; VES Diverter may also include an optional water-soluble organic salt and/or alcohol to improve viscoelasticity under severe conditions. Diversion with VES Diverter may be temporary or permanent. The micelles are broken by dilution by formation water or by contact with hydrocarbons, but the surfactant molecules remain intact. Some surfactants sometimes cause emulsions when they contact certain oils; if this occurs in fracturing or in carbonates it is unlikely to cause damage if the carbonate acidizing left large wormholes and if the fracturing left large flow paths; flow through these is unlikely to be impeded by the presence of emulsions. However, emulsions could impede flow through the smaller flow paths remaining after sandstone acidizing, or if small fractures or small wormholes were created.
It is also known to use self-diverting acids, typically consisting of hydrochloric acid mixed with a polymeric gelling agent and a pH-sensitive cross-linker, in matrix acidizing. Self-diverting acids are typically designed to gel at intermediate pH values, when the acid is partially spent. Self-diverting systems that are not based on cross-linked polymers but which rely upon viscoelastic surfactants are described in U.S. Pat. No. 4,695,389 (see also, U.S. Pat. No. 4,324,669, and British Patent No. 2,012,837, both cited there)—which has a common assignee as the present application. Viscoelastic surfactants based systems exhibit very low friction pressure and therefore are easy to pump and yet, form a gel downhole. U.S. Pat. No. 4,695,389 discloses a viscoelastic surfactant-based gelling agent intended for use in acid fracturing. The particularly preferred embodiment is a fluid comprised of N,N-bis(2-hydroxyethyl) fatty amine acetic acid salt (the gelling agent), an alkali metal acetate salt, acetic acid (the acid—which actually removes the damage from the formation), and water.
Another chemical diverter system based on VES technology has been described in U.S. Pat. No. 6,399,546 which has a common assignee as the present application. This material, called a “Viscoelastic Diverting Acid” (VDA), is typically made from surfactants made from betaines, which we will call BET surfactants, and others, that are described in U.S. Pat. No. 6,258,859. VDA fluids are used for diversion in acidizing or acid fracturing treatments. VDA fluids are made from mixtures of strong acids, such as HCl, and BET surfactants. These materials are ungelled when strongly acidic as pumped, but as the acid “spends” or is consumed, and the pH rises and the electrolyte content of the fluid increases (typically by introduction of calcium ions as a consequence of the dissolution of carbonates) the fluids gel. Thus, when first injected they enter the most permeable zone(s), but when they gel they block that zone and divert subsequently injected fluid into previously less-permeable zones.
Other improved self-diverting systems have been described in U.S. Pat. No. 6,399,546, having a common assignee as the present application, and its corresponding International Patent Application WO 01/29369. This application, hereby incorporated by reference, provides formulations, suitable for acid treatments, comprising an amphoteric surfactant that gels as the acid spends in the presence of an activating amount of a co-surfactant and of multivalent cations typically generated by the acid reaction with the formation. When the gelling agent is mixed in hydrochloric acid, the co-surfactant prevents the gelling of the solution; the solution gels when the pH increases above about 2.
GB Patent Application No. GB 0103449.5, assigned to the same assignee as the present application, describes cleavable surfactants containing chemical bonds such as acetals, amides or esters that can be broken by adjusting the pH. Examples show some that are broken by very dilute acetic acid (0.5 to 1%) at temperatures below about 60° C. and some that can be broken when the pH is raised above about 8. That application states that cleavable surfactants are useful in wellbore service fluids, especially fracturing fluids and well clean-out fluids.
Methods have been developed that would destroy the micellar structure of some VES fluids if they were being used as diverters. U.S. Patent Application Publication No. US 2002/0004464 A1, which has a common assignee as the present application, teaches that certain carboxylic acids, that have charges opposite to the VES's head group can act as breakers by destroying the micellar structure of the VES fluid. It also teaches that some organic acids, such as adipic, citric, or glutaric acids, in the protonated form can act as breakers. On the other hand, for certain surfactants, organic acid salts such as salicylates can be stabilizers. That application teaches that whether or not an organic acid acts as a VES breaker depends upon whether the surfactant is anionic, cationic, zwitterionic or nonionic. It focuses on breakers for viscoelastic surfactant systems based upon cationic surfactants such as erucyl methyl bis(2-hydroxyethyl) ammonium chloride and zwitterionic surfactants such as betaine surfactants and teaches only breakers that function by destroying the micellar structure of the VES fluid.
Often, diversion methods either cause damage by leaving behind particles, polymer, sludge, precipitates, surfactants, etc. and/or are expensive and complicated and/or require specialized equipment and facilities (for example to generate, monitor and control foams). Also, many chemical diverters cannot be used at high temperatures or are incompatible with some chemicals (such as strong acids or very low or very high salt concentrations). There exists a need for simple compositions and methods for diversion of injected fluids, especially acidic fluids, at high temperatures, in which the diverters are completely broken at predetermined times or conditions after the main treatment is completed. There is also a need for chemical diverter systems that after degradation do not leave behind decomposition products that are surfactants, polymers or crosslinked polymer fragments.